Subsea Processing of Crude Oil

ABSTRACT

A subsea production unit for subsea treatment of oil has a frame that supports an onboard multiphase separation system for separating gas and water from a wellstream containing oil, and an onboard water treatment system for cleaning oil from water that is produced by the separation system.

This invention relates to subsea processing of crude oil, especially toseparate water from a subsea wellstream for the purpose of flowassurance and to dispose of that water without damaging the marineenvironment.

Specific aspects of the invention relate to the challenges of developingmarginal subsea oil fields, including small, remote or inaccessiblefields. To address those challenges, the invention aims to reduce thecost of production and related capital investment. The invention alsoeases the installation and operation of the necessary subseainfrastructure.

A typical subsea oil production system comprises production wells eachwith a wellhead, pipelines running on the seabed, structures to supportvalves and connectors, manifolds and risers to bring production fluidsto the surface. At the surface, a topside installation that can be aplatform or a vessel receives the production fluids before their onwardtransportation.

Crude oil is a multiphase fluid that generally contains sand, oil, waterand gas. These components of the wellstream interact in various waysthat tend to decrease the flow rate in the production system, from thewellhead to storage. A critical failure mode in crude oil production isclogging or plugging of pipelines by solids because remediation of suchblockages can be extremely expensive, especially in deep water.

When the temperature of a wellstream decreases below a certainthreshold, at a given pressure, components of crude oil may reacttogether or individually to coagulate or precipitate as solid wax,asphaltenes or hydrates that could plug a pipeline. For example, waxwill typically appear in oil at a temperature of around 30° C.

As crude oil is hot at the outlet of the wellhead, typically around 200°C., one approach in subsea oil production is to maintain the oiltemperature above the critical threshold until the oil has beendelivered to a topside installation. There, the oil can be treated toallow the treated oil to be transported at ambient temperature intankers or in pipelines. For example, multiphase separation may beperformed at the topside installation, as disclosed in WO 2015/167778.WO 2007/085900 discloses another typical topside separation unit, inthat case comprising gravity tanks and at least one pump.

Two main approaches are known in the art to reduce the cost of producingoil from subsea fields, especially marginal subsea fields. The firstapproach is to simplify subsea equipment as much as possible, forexample by using a long, insulated pipeline extending from a wellheadand minimal additional equipment subsea. The second approach adopts anopposite tactic, namely to transfer at least some conventionally-topsideproduction and storage functions to a subsea location for intermittentexport of oil by tanker vessels. For example, EP 1554197 discloses theuse of a subsea storage tank as temporary storage, inside which oil andwater in the wellstream will eventually separate.

A challenge of the first approach is that pipeline cost becomes a largeelement of development cost where fields are isolated or remote. In thisrespect, conventional solutions to maintain oil temperature employ ‘wet’thermal insulation, which involves covering the pipeline withthermally-insulating materials. The pipeline may also be heated byelectrical heating or by heat transfer from hot fluids. However, as somepipelines may be very long, for example longer than 100 km, suchsolutions can become very expensive.

Also, in view of oil viscosity, it may be necessary to employ boostingor multiphase pumping to manage slugs in pipelines. For example, WO2011/051453 and WO 2007/140151 disclose booster pump systems. The use ofbooster multiphase pumps may maintain sufficient pressure in the flow toavoid plugging but it does not allow a sufficient reduction of coatingthickness to overcome the related disadvantages in long pipelines.

For these reasons, the present invention is concerned with the secondapproach, which involves subsea processing and storage of produced oil.By displacing at least some oil processing steps from the topside to theseabed, thermal insulation or heating can be reduced and ideally, inprinciple, removed. The invention is particularly concerned with thechallenges of dealing with a wellstream that is of insufficient qualityto be stored and transported, which makes it necessary to process thewellstream subsea.

The prior art features several proposals for subsea processing inconnection with the exploitation of subsea oil fields. For example, WO2017/001567 discloses a typical water re-injection system, in whichwater for injection is extracted from seawater. Similarly, in WO2017/010892, salt is extracted from seawater to allow re-injection ofwater into a well. Chemicals may also be added to the re-injected water.

In order to reduce the need for thermally-insulating coating or forheating of pipelines, ‘cold flow’ technologies are being developed. Theprinciple of cold flow relies upon removing as much water as possiblefrom the wellstream so that coalescing or deposition of wax, asphalteneor hydrates does not start or at least can be mitigated before pluggingof the pipeline occurs. The Applicant's WO 2014/095941 describes anexample of a cold flow installation. WO 2016/195842 discloses othertypes of cold flow reactors.

Subsea water/oil separation systems are known in the art but theirperformance is not sufficient for cold flow installations. The subseaseparation process as a whole has to be improved over such prior art toreach an appropriate level of performance, which may be expressed interms of the Water-in-Oil (WiO) ratio.

Efficient water/oil separation systems are known for topside or onshoreuse. However they tend not to be a good solution for subsea use becauseof the difficulty of supplying high electrical power under the sea overlong distances. For this reason: hydrocyclone-based separation should beavoided. Also, such separators need maintenance that cannot be donepractically subsea. Gravity separators should also be avoided becausethey require atmospheric pressure, which would prevent the productionfluid flowing up to the surface.

More generally, there is a need in so-called ‘brownfield’ developmentsto improve the flow conditions within existing tie-back lines due togradually-increasing production of water over the lifetime of a subseafield. Also, as areas mature, new reservoirs are revealed, and new wellsare either daisy-chained or tied-in towards existing tie-back lines.Alternatively, new fields are tied-back to existing facilities, withlarge associated topside costs.

In these circumstances, the additional flowrate can lead to‘overflooding’ of the existing lines as those lines are not designed tohandle the additional producers. The conventional way of dealing withthis has been to lay new lines or to choke some producers to address theproblem temporarily at the seabed, and then to effect topsidemodifications to add separation capacity. The latter can be extremelyexpensive.

A particular issue is that as many subsea fields mature, the typicalincrease in water production in the wellstream over time will increasethe need to dispose of that water, which generally contains oil. This isagainst the background of ever more stringent environmental regulations,which mean that the Oil in Water (OiW) ratio is typically much too highto allow the produced water to be released directly into the sea. Ingeneral, therefore, water produced after separation has been treated byinjecting chemicals, stored subsea or recovered to the surface by awater pipeline. None of those solutions are wholly desirable, eithereconomically or environmentally.

In some field developments, the strategy has been to avoid production ofwater to the surface by using down-hole water separators. These separatewater from oil or gas streams down-hole for dissipation into suitablegeological formations. Whilst these solutions can eliminate productionof waste water, they are not always practically possible or economicallyviable.

Another way to manage produced water is to inject the produced waterinto the petrological formation from which it came, or into anothersuitable formation. This involves transporting produced water from theproducing site to the injection site, and pumping to achieve a suitableinjection pressure. It also increases the risk of oily water escapinginto the sea.

WO 2016/108697 teaches a combination of subsea separation units forremoval of sour components, in particular sour gas, from an oil streamin order to reduce corrosion of subsea piping and equipment. However,this does not remove enough water from the oil to allow subsea storageof the oil.

WO 2008/051087 discloses a subsea water-oil separation system for waterre-injection. Its teaching is to heat the separator to improve thewater-cut in oil.

US 2016/138762 discloses another subsea processing arrangement thatinjects a catalyst chemical and then separates that chemical.

Whilst compact subsea production units are known, there remains a needfor simpler systems that will allow cost-effective development of small,remote oil fields.

WO 2017/027943 discloses an integrated compact station with subsea fluidseparation and pumping systems. Separation of a wellstream is effectedby a harp-type gravitational gas-liquid separator to separate gas fromliquid and by a liquid-liquid separator to separate water from oil.

In some embodiments of WO 2017/027943, the liquid-liquid separator mayhave a frusto-conical section with a series of control valves. Ahydrocyclone is preferred. Conversely, in another embodiment of WO2017/027943, a horizontal gravitational pipe separator performsliquid-liquid separation. However in that latter embodiment, the pipeseparator is located outside, and connected to, the compact structurebecause the pipe separator takes significant space. Thus, WO 2017/027943teaches that the pipe separator is too bulky to be integrated within thestructure and so has to be separated from the structure when a pipeseparator solution is chosen for liquid-liquid separation.

A harp-type gas separator is also disclosed in WO 2006/098637, whichfocuses on gas separation and also teaches combining the harp separatorwith a pipe separator for liquid-liquid separation.

WO 2005/005777 discloses a conventional pipe separator whose separationefficiency is insufficient for the purpose of cold flow.

WO 03/033872 discloses a system comprising a pipe separator and anelectric coalescer that, beneficially, has no moving parts. However,this approach also achieves poor separation efficiency and requires apump to repressurise the fluid because of head loss. WO 2013/179252 alsodiscloses an electric coalescer like that of WO 03/033872.

A coalescer is usually mounted downstream of a water/oil separator.However, in WO 2004/007908, a coalescer is located upstream of awater/oil separator to produce bigger droplets that are more easilyseparated in the separator.

WO 2014/096330 describes a dual pipe separator or DPS, referred to inthat document as a tubular oil separator, which differs from a standardpipe separator in that the separator is inclined for greater efficiency.A DPS is also more compact than a pipe separator.

U.S. Pat. No. 6,197,095 relates to a system and method for subseamultiphase fluid separation. The system may be of modular construction,the modules being secured in a frame to be lowered as a unit to the seabed. Against this background, the invention provides a subsea productionunit for subsea treatment of oil, the unit comprising a frame thatsupports: an onboard multiphase separation system for separating gas andwater from a wellstream containing oil; and an onboard water treatmentsystem for cleaning oil from water that is produced by the separationsystem.

The water treatment system may comprise a gas inlet communicating withthe separation system and is arranged to mix the produced water with gasseparated from the oil. The water treatment system may have a furtherinput to receive water settling in a storage tank, which storage tank issuitably an onboard tank also supported by the frame.

The water treatment system suitably comprises at least one flotationunit having: a water inlet for water to be cleaned of oil; a wateroutlet for water cleaned of oil; and a reject outlet for gas mixed withoil cleaned from the water. For example, there may be first and secondflotation units in series, the water outlet of the first flotation unitcommunicating with the water inlet of the second flotation unit. The oreach flotation unit suitably communicates with a mixer for mixing gaswith water to be cleaned of oil;

The water treatment system may comprise a discharge outlet for dischargeof the cleaned water into surrounding seawater and/or may communicatewith a water injection system for injecting the cleaned water into asubsea reservoir. In that latter case, the water injection system maycomprise a gas inlet communicating with the separation system and isarranged also to receive and inject gas separated from the oil. Thewater injection system may also comprise a processed water inletcommunicating with a seawater processing system and is arranged also toreceive and inject processed water drawn from surrounding seawater.

An oil-in-water sensor is suitably associated with a cleaned wateroutlet of the water treatment system.

The separation system may comprise a gas separator upstream of awater/oil separator. In that case, the gas separator and the water/oilseparator are suitably at corresponding longitudinal positions withrespect to a length direction of the unit.

The gas separator may be beside the water/oil separator and fluid flowthrough the water/oil separator may be in a substantially oppositedirection to fluid flow through the gas separator with respect to thelength direction.

A water-in-oil sensor is suitably associated with an oil outlet of thewater/oil separator.

The water/oil separator may comprise at least one dual pipe separator,for example an array of parallel dual pipe separators.

A pre-separator pipe section is suitably positioned upstream of the oreach dual pipe separator. The pre-separator pipe section may be foldedsinuously to define upper and lower portions in mutually-stacked,vertically-spaced relation. Those upper and lower portions of thepre-separator pipe section may have mutually-opposed inclination. Theflow direction suitably reverses between the upper and lower portions ofthe pre-separator pipe section.

The upper and lower portions of the pre-separator pipe section mayincline upwardly in a flow direction within each portion, and may bestacked above the dual pipe separator.

The separation system suitably further comprises a sand removal unitupstream of the gas separator. In that case, a retrievable sand storagetank may receive sand from the sand removal unit.

Components of the respective onboard systems are suitably replaceablemodularly subsea by lifting, without lifting the frame. For thispurpose, the frame may defines upwardly-opening silos arranged toaccommodate the respective components. The components may then besupported in respective transport and installation structures that areengageable with the silos of the frame for vertical movement relative tothe frame on installation or removal.

Conveniently, the frame is a unitary structure that is transportable bytowing or lifting while supporting components of the respective onboardsystems.

The inventive concept also embraces a method of separating fluids from amultiphase oil-containing wellstream. The method comprises: separatinggas and water from the wellstream to produce oil; and cleaning oil fromthe water that is produced by the separation step; the separation andcleaning steps both being performed subsea onboard a transportablesubsea production unit. The method may therefore be preceded or followedby transporting the subsea production unit to or from a subsea location.

The cleaning step suitably comprises mixing the produced water with gasseparated from the wellstream in the separation step. The cleaning stepmay be performed also on water settled from oil produced by theseparation step.

Oil is suitably cleaned from the produced water by passing the producedwater through at least one flotation unit, for example by passing theproduced water through first and second flotation units in series, thewater output from the first flotation unit being input to the secondflotation unit.

The produced water may be discharged into surrounding seawater aftercleaning, suitably while maintaining an oil-in-water ratio of thedischarged produced water below 30 ppm.

The produced water may be injected into a subsea reservoir aftercleaning. Processed water drawn from surrounding seawater and/or gasseparated from the wellstream in the separation step may be injectedwith the produced water.

Gas separation is suitably effected on the wellstream upstream of waterseparation on the wellstream. Water separation may be performed in atleast one dual pipe separator.

The wellstream may be conditioned in a pre-separator pipe sectiondownstream of gas separation and upstream of the dual pipe separator.The wellstream may be guided to follow a sinuous path in thepre-separator pipe section, and may reverse in flow direction in thatpipe section.

The invention separates the wellstream efficiently to enable subseastorage and offloading of oil. The result is a flexible, low-cost subseafield development with low power consumption that requires a minimum ofresources to develop anywhere in the world. It is also simple torelocate the apparatus of the invention between subsea oil fields whenone field has been exhausted and another marginal field elsewhere is tobe exploited.

Embodiments of the invention introduce a manifold, sand removal, aseparation process, a water treatment process and a water and gasinjection process. Power may be provided via either a submerged powerbuoy or a power and control umbilical.

Initially, in embodiments of the invention, the manifolded wellstreamflows through a cyclonic de-sander that reduces the effect of any sandentrained in the wellstream. Any sand collected by the de-sander may,for example, be dumped into a removable sand storage tank.

Next, the wellstream flows through a gas-separation unit, preferably amarinised harp gas separator, to remove a major portion of gas from thewellstream. This improves the effectiveness of subsequent separation ofwater from oil.

Then, the degassed liquid part of the wellstream flows into at least onedual pipe separator (DPS), preferably a parallel array of DPSs, fromwhich oil will then flow directly into a subsea oil storage tank, forexample inside an inflatable bag. The oil storage tank is suitablytowable, preferably being supported by the same rigid frame thatsupports other elements of the system.

Water from the DPS is fed into a marinised water treatment system. Thewater treatment system comprises one, two or possibly more CompactFlotation Unit (CFU) stage(s) to enable reinjection of produced watercontaining oil at a level of, preferably, <100 ppm, or subsea dischargeof produced water containing oil at a level of, preferably, <30 ppm.

Gas can be added to the produced water line upstream of a waterinjection pump. The water injection pump may be a single-phase pump or amulti-phase pump but can typically handle up to 10% gas by volume mixedwith the produced water.

Only a bulk separation of oil and water is necessary before oil isstored in the storage tank. Typically, therefore, the oil flowing intothe storage tank will still contain 5%-10% water by volume. Thereafter,the tank will work as a settling tank, which separates water from theoil effectively to an export quality.

Water accumulating in the lower part of the storage tank may be pumpedback to the process upstream of the water treatment system. Conversely,any gases collecting at the top of the storage tank may be flushed backto the produced water line upstream of the water injection pump.

Offloading of oil from the storage tank to a transport tanker at thesurface may be effected via a flexible offloading system in shallowwater. If the water is too deep for that solution to be used, adeep-water riser system may be used instead in combination with anoffloading system at its upper part.

Processing units may be integrated into the system by means of transportand installation frames allowing modular plug-and-play functionality.The entire plant, or certain key components of the plant, are suitablylocated inside a supporting frame as a subsea production unit.

In principle, as noted above, other water separator designs like gravityseparators or pipe separators could be used for bulk separation.However, such separators are too bulky for the purposes of theinvention. Similarly, hydro-cyclone technologies could be applied forcleaning of water but it would be challenging to provide sufficientpower for such equipment subsea. Also, the handling of sand issimplified in the system of the invention.

In summary, therefore, embodiments of the invention provide a compactsystem for subsea treatment and storage of oil. The system comprises aframe, that frame comprising or supporting a multiphase separation unitand a water treatment unit. Conveniently, the units may be replaceablesubsea without lifting the frame.

The multiphase separation unit suitably comprises, in succession: a sandremoval unit; a gas-separation unit, preferably a harp gas separator;and a water-oil separation unit. A retrievable sand storage tank may beincluded to hold particulate material output by the sand removal unit.

The water treatment unit suitably comprises at least one pump.

A subsea storage tank, which may be heated, may be provided forreceiving oil from the multiphase separation unit. Conveniently, thesubsea storage tank can also be mounted on the frame.

The subsea storage tank suitably comprises outlets for residual waterand gas that settle in that tank and return lines leading from thoseoutlets to, respectively, the water treatment unit and a gas outlet.Conversely, an oil outlet of the storage tank suitably feeds a riser orexport line for supplying oil to a tanker vessel at the surface.

The frame may also comprise or support a water reinjection unit, Such aunit suitably mixes gas with water and re-injects that water via adedicated well.

Any or all of the above components or units may be mounted on the sameframe.

A control system suitably monitors all of the units and actuatesrelevant valves to ensure correct operation. The control system may becontrolled from the surface and/or may be automated.

The invention provides a subsea water management system that combinesseabed bulk separation with associated treatment of produced water. Theobjective of this process is to remove bulk water from an existingflowline system to make space for more hydrocarbons.

Bulk separation of water followed by subsea water treatment for dumpingor re-injection is an effective way of increasing the use of existingsubsea infrastructure in brownfield areas. As noted above, newdiscoveries increase the requirement for additional flowline tie-backsfor well streams. By virtue of the invention, the use of existinginfrastructure can be considered instead of having to install newtie-backs in this situation.

A common location for the water management system of the invention willbe at the end of an existing tie-back line from an existing subseafield. A manifold suitably gathers well streams at a central locationupstream of the flowline to be used. If additional well streams arebeing co-mingled with already existing infrastructure, subsea tie-inpoints must be developed to connect the in-field flowlines to themanifold before entry into the common transport line.

In general, optimising the position of the water management system willdepend upon the layout of the particular field. It is advantageous toenable a flexible connection without having to re-build much of theexisting structure. In that case, large savings of both cost and timemay be achieved by increased utilisation of existing infrastructureinstead of laying new pipelines for new well streams. In addition, anyresidual water can be handled easily at the surface, without largetopside modification costs.

Embodiments of the invention provide a complete subsea factory on thesmallest possible scale. The invention differs from known cold flowsolutions in that a wax control unit and tie-back lines are avoided byadding subsea storage units and an offloading system instead. As thereis no need for tie-back lines, there is no need for booster pumpstations and there is much less need for chemicals. Consequently, theinvention reduces overall power and chemical consumption dramatically incomparison with existing cold flow solutions.

Whilst some embodiments of the invention are particularly apt to be usedin smaller fields, their solutions are relevant also for exploitinglarger fields.

The invention also provides a subsea multiphase fluid separation system.The system comprises: a harp separator for gas separation; and awater-oil separation stage, the water-oil separation stage comprising atleast one dual pipe separator; and a water treatment system. The watertreatment system may be capable of ensuring that the residual oil inwater concentration, after water treatment, is below 10 ppm.

The system need not contain moving parts, hence relying upon passiveseparation, and need not comprise a pump.

The water treatment system may comprise a water outlet to the sea and/ora water line, for example leading to another subsea location or to thesurface.

The water-oil separation stage may further comprise an electrocoalescerand a second separator in series. Preferably the second separatorcomprises a second dual pipe separator. It is also possible for elementsof the water-oil separation stage to be, in series, a dual pipeseparator, a coalescer and a single pipe separator.

The elements of the system may be mounted on a unique frame, or in, oron, a common structure.

A monitoring system at the outlet of the water treatment system suitablymeasures the Oil-in-Water ratio and controls the flow rate to eachelement of that system.

Similarly, a monitoring system suitably measures the Water-in-Oil ratioat the outlet of the water-oil separation stage and controls the flowrate to each element of that stage.

Thus, the invention recognises the benefit of separating oil and waterbefore further wax control treatment to enable long-distance transport.A reduction of the WiO content to below 1% may be beneficial to reducethe amount of chemicals required to avoid the formation of hydratesalong a long-distance tie-back line at ambient temperature.

It is challenging to separate out the residual 1% to 2% of water fromoil before long-distance transport. Subsea separation of water from oilto a sufficiently low level is achieved in the invention by applying aset of processing functions as described herein. The well stream flowsthrough a gas harp to remove most of the gas. Then, the liquid partflows into a first-stage DPS. Oil flows through an in-line electrostaticcoalescer before entering a second-stage DPS. Water enters a watertreatment system that comprises one CFU stage for reinjection of waterand two CFU stages for discharging water into the sea. If water is beingreinjected, then gas can be added to the produced water line before awater injection pump. Alternatively gas may be returned to a multi-phaseflowline to be transported with oil to the host.

In order that the invention may be more readily understood, referencewill now be made, by way of example, to the accompanying drawings, inwhich:

FIG. 1 is a schematic diagram of a subsea processing system inaccordance with the invention;

FIG. 2 is a schematic side view of a pre-separator pipe section of thesystem of FIG. 1, in longitudinal section;

FIG. 3 is a schematic side view of a dual pipe separator in longitudinalsection, which is positioned in the system of FIG. 1 immediatelydownstream of the pre-separator pipe section exemplified in FIG. 2;

FIG. 4 is a perspective view of a subsea production unit in accordancewith the invention installed on the seabed, showing a functional modulebeing removed from a surrounding frame of the unit to be lifted to thesurface for servicing;

FIG. 5 is a perspective view showing the positional layout of variousfunctional modules of the subsea production unit of FIG. 4, with theframe of the unit omitted for ease of viewing;

FIG. 6 is a schematic detail side view showing the compact arrangementof a pre-separator pipe section and a dual pipe separator in the layoutshown in FIG. 5;

FIG. 7 is a block diagram of alternative subsea degassing and waterseparation facilities, showing an additional pipe separator stage forwater separation;

FIG. 8 is a block diagram corresponding to FIG. 7 but showing anadditional dual pipe separator stage for water separation; and

FIG. 9 is a schematic process flow diagram corresponding to thearrangement shown in FIG. 8.

It should be noted that conventional piping equipment, such as somevalves, may not be represented in these simplified drawings for clarity.

Referring firstly to the subsea processing system 10 shown in FIG. 1 ofthe drawings, this system has optional provisions for water dischargeand for water re-injection. Water re-injection may be beneficial tomaintain reservoir pressure, either to maintain or to increaseproduction.

In the system 10 shown in FIG. 1, a wellstream of production fluidsflows from a subsea production wellhead 12 via a conventional ‘Christmastree’ structure 14 installed on top of the wellhead 12.

Optionally, the wellstream flows into a production header 16 that servesas a manifold to divide the flow into parallel paths. Processing of theportion of the wellstream on one of those parallel paths will now bedescribed, it being understood that other portions of the wellstream onthe other paths may undergo similar parallel processing steps. Theoutputs of those parallel processing steps may be combined at anyconvenient stage.

Initially, the wellstream may flow through a cyclonic de-sander 18 toremove substantially all of the sand that may be entrained in theproduction fluids. Such sand could otherwise promote erosion, corrosionor clogging of the pipework and equipment downstream. Other de-sandingtechnologies are known, for example those that employ gravity.

Conventionally, sand management generally relies upon down-hole systemssuch as sand screens or gravel packs. However, such down-hole systemscannot always be used because they can impair production. Even whendown-hole systems are used, any failure that causes sand to be producedwill have to be managed by back-up systems.

Oily sand removed by the de-sander 18 is conveniently dumped into aremovable sand storage tank 20, which can be raised to the surfaceperiodically for topsides treatment or disposal of the sand within andto be replaced with an empty sand storage tank 20. This solution ispractical for low to moderate rates of sand production. Higher rates ofsand production can be managed by instead re-combining the removed sandwith the production fluids after subsea processing, for later separationand clean-up topsides.

Next, the de-sanded wellstream flows through a bulk gas separation unit,exemplified here by a harp gas separator 22. This removes a majorportion of the gas in the wellstream, which is output from an upperbranch of the gas separator 22 as wet gas. Some gas will remain in thewellstream downstream of the gas separator 22, but not to a problematicextent. In any event, much of that residual gas will be removed insubsequent subsea processing steps, as will be explained.

The substantially-degassed liquid portion of the wellstream flows fromthe gas separator 22 into a bulk water separation unit, exemplified hereby dual pipe separators (DPSs) 24 operating singly or preferably inparallel. This bulk water separation step removes a major portion of thewater from the wellstream, which is output from the DPSs 24 as oilywater. Typically, however, the resulting oil will still contain 5% to10% of water by volume.

More specifically, in practical embodiments, the mainly liquid flowdownstream of the gas separator 22 enters a manifold that divides theflow into a number of branches corresponding to the number of DPSs 24 ina parallel array. The number of parallel DPSs 24 may be chosen forspecific installations based upon factors such as the reservoirproduction profile, the results of high-pressure separability testsperformed on production fluids during design qualification, andrequirements for flexibility through the design life of the system 10.

From the manifold, each DPS 24 is preceded by a substantially horizontalpre-separator pipe section 26 of typically 5 to 10 metres in lengthbefore the flow enters the upwardly-inclined DPS 24 itself. In thisrespect, reference is made to FIG. 2 of the drawings, which shows thelayered flow of oil 28 and water 30 along a pre-separator pipe section26 and the mixing characteristics of those layers 28, 30 at differentpoints along its length.

The flow is pre-separated within the pre-separator pipe section 26before entering the DPS 24 through an inlet 32 at the lower end of theDPS 24, as shown in FIG. 3. The flow velocity in the pre-separator pipesection 26 is controlled to be typically between 0.5 to 1.5 m/s,depending upon the length of that section. Typically, the flow willpre-separate in that section 26 for about five to ten seconds beforeentering the DPS 24 itself.

With reference to FIG. 2, the principle underlying these pre-separationparameters arises from the observation that the established dispersionband 34, or the phase between oil 28 and water 30, diminishes rapidly ifthe flow velocity differs between these two principal liquid phases.This velocity requirement is fulfilled if a slightly-upward pipe bend of10-15 degrees from the horizontal is provided at the inlet 32 of the DPS24, corresponding to the outlet of the pre-separator pipe section 26 asshown in FIG. 2.

FIG. 3 shows that the inlet 32 of the DPS 24 carries the pre-separatedoil 28 and water 30 into a flared and perforated inner pipe 36 of theDPS 24. The inner pipe 36 is concentric with and contained within aclosed outer pipe 38 of the DPS 24 and extends just over halfway alongthat outer pipe 38.

A velocity difference between the oil 28 and the water 30 is establisheddue to the specific gravity differences between those liquids as theyclimb within the upwardly-inclined DPS 24. This density difference alsoimproves separation of water 30 dispersed in the oil 28, causing theheavier water 30 to sink and the lighter oil 28 to rise within the outerpipe 38 of the DPS 24.

The outer pipe 38 has a water outlet 40 at its lower end and an oiloutlet 42 at its upper end to draw off the respective liquid outputs 28,30. As noted above, it is inevitable that the oil output will containsome water and that the water output will contain some oil in practice.

Preferably, in practical embodiments, the geometry of the pipeworkbetween the gas separator 22 and the DPS 24 creates a liquid lock bylocating the top of the water outlet 40 of the DPS 24 at substantiallythe same level as the inlet to the gas separator 22. This liquid lockprevents carry-under of gas and ensures that the pre-separator pipesection 26 is mainly water-filled. As incoming oil 28 is forced throughthe water 30 in the liquid lock, separation will occur.

The separation of water 30 from oil 28 is suitably controlled usingknown capacitance measurement technology. The set location of the waterlevel in the DPS 24, being the interface of emulsion 44 between oil 28and water 30, may be monitored to control a water outlet valve (notshown) accordingly.

The use of compact DPSs 24 ensure a small footprint, retrievability andeffective separation of oil 28 and water 30. Their small-diameterpipework facilitates the use of the system 10 in the full depth rangefrom shallow to ultra-deep waters.

It has been found to be beneficial to remove free gas from thewellstream before the remaining liquid enters the bulk water separationunit comprising the pre-separator pipe section 26 and the DPS 24. Freegas could otherwise adversely influence the flow, producing a slug flowpattern. In this respect, the vertical pipes of the harp gas separator22 provide a large volume to absorb the fast-arriving fluids and toprovide sufficient volume for the free gas. Thus, the gas separator 22suppresses slugs to smooth the liquid flow entering the bulk waterseparation unit, in addition to removing the free gas.

Consequently, by separating gas from liquid in the wellstream, the bulkwater separation unit performs subsequent water separation moreeffectively. Synergistically, the separated gas is also used forcleaning residual oil from the separated water, allowing the separatedwater to be discharged or re-injected as will be explained below.

Oil flowing from the DPS 24 is channelled directly into a heated subseaoil storage and stabilisation tank 46. which settles and separates inthe tank 46 into an oil layer of export quality atop a layer of oilywater. The oil may be offloaded periodically from the tank to a shuttletanker 48 at the surface, via a flexible offloading system 50 in thisshallow-water example. Conveniently, the shuttle tanker 48 can carry thepumping equipment that is necessary to draw oil from the tank 46.

Wet gas accumulating at the top of the oil storage and stabilisationtank 46 is drawn off to be combined with the wet gas flowing from thegas separator 22. Conversely, a water removal pump 52 draws accumulatedoily water from the lower part of that tank 46. The oily water from thetank 46 is combined with the oily water output from the DPSs 24, andwith any oil that may have settled out from the oily sand held in thesand storage tank 20. By way of illustration, oil may initially bepresent in the resulting combined flow at a level of >4500 ppm.

The oily water then enters a water treatment system 54. In this example,the water treatment system 54 comprises a series of two compactflotation unit (CFU) stages. In each stage, a mixer 56 mixes incomingoily water with some of the wet gas output from the gas separator 22.The resulting mixture of oily water and gas is then separated in a CFU58 into an output of treated water and another output of a gas/oilmixture.

A CFU 58 is a multiphase separator that needs no moving parts andrequires no external energy input. It is reliable and highly efficientin separating water, oil and gas to produce high-quality treated water,even with a short retention time.

The CFU 58 comprises a hollow cylindrical vessel that is resistant tohydrostatic pressure. That vessel defines an internal flotation chamberthat is generally circular in horizontal cross-section. Incoming oilywater enters the chamber substantially horizontally and tangentially toimpart swirl. The separation process is aided by internal features ofthe vessel and by a gas flotation effect caused by the release ofresidual gas from the water and/or by added gas.

These combined processes act on fluid components of different specificgravities. Small oil droplets are caused to agglomerate and coalesce toproduce larger oil droplets, making it easier to separate them fromwater. A continuous oil or emulsion layer is created at an upper liquidlevel of the flotation chamber, while treated water exits through thebottom of the vessel. On occasion, however, process optimisation mayinvolve the introduction of external gas and/or flocculants.

The separated gas/oil mixture is removed continuously from the CFU 58via an outlet pipe suspended at the top of the vessel. This multiphasereject flow may be controlled by a valve in the outlet pipe. The liquidflow rate of the reject flow is typically about 1% of the overall inletwater flow to the CFU 58, and the oil content in that liquid istypically 0.5% to 10%.

By way of example, a CFU 58 having a flotation chamber with anoperational volume of just 2.4 m³ can treat a water flow of up to 220m³/h (33 000 bpd). Higher flow rates can be achieved by arrangingmultiple CFUs 58 in parallel.

The CFU 58 in the first stage of the water treatment system produces anoutput of partially-treated water with a much-reduced oil content ofabout 100 ppm, which serves as the water input into the mixer 56 of thesecond stage of the system. The CFU 58 in the second stage furtherreduces the oil content in the partially-treated water so as to outputfully-treated produced water that preferably contains oil at a level of<30 ppm, for example 9 ppm.

The outputs of gas/oil mixture from the successive CFU stages arecombined and fed into a gas/oil separator 60, which is exemplified hereby a gas/oil knockout drum. The gas/oil separator 60 outputs oil thatmay still contain a minor fraction of water. That oil is fed into theoil storage and stabilisation tank 46 to settle and separate out beforebeing offloaded. The gas/oil separator 60 also outputs wet gas, which iscombined with the wet gas flowing from the gas separator 22.

The produced water from the two-stage water treatment system 54 is cleanenough to be discharged, optionally, directly into the sea via a valve62 and a discharge outlet 64. Alternatively, the produced water can bere-injected into the well, conventionally via a Christmas tree structure66 atop a water/gas injection wellhead 68. In that latter case, thesecond stage of water treatment could be omitted.

An oil-in-water sensor in a flowmeter 70 measures the oil concentrationin the produced water to ensure that the concentration is belowappropriate thresholds, for example <100 ppm for re-injection or <30 ppmfor discharge to sea.

The ability to discharge or to re-inject the produced water savesvaluable space in oil transport lines, increasing the amount of oil thatcan be produced using the available infrastructure. For example, bulkseparation of typically 50%-75% of water from the wellstream allows fortie-in of more wells to a manifold.

Subsea discharge of produced water has other important benefits. Forexample, it eliminates the need to transport large volumes of water fromproduction sites to tieback hosts, reducing the cost of the productionsystem. This benefit increases with water depth and tie-back distance.

By decreasing hydrostatic pressure on subsea production flowlines,subsea discharge of produced water helps to reduce back-pressure on asubsea wellhead and allows for more production. The resulting effectprovides additional economic benefits to justify the capital expenditurefor the plant.

Subsea discharge of produced water also minimises the topside equipmentfootprint and so protects much of the production equipment from damageby bad weather.

For the purpose of re-injection, the produced water passes through awater/gas injection system 72. Here, the wet gas flowing from the gasseparator 22, supplemented with wet gas from the gas/oil separator 60and from the oil storage and stabilisation tank 46, is combined with theproduced water to be re-injected.

In the water/gas injection system 72, the produced water is fed via aone-way valve to a water injection suction header 74, from which amultiphase water injection pump 76 draws the water and outputs the waterto the Christmas tree structure 66 under pressure. The water flowingthrough the water injection pump 76 may contain up to about 10% gas byvolume.

Optionally, as shown, the pressurised water from the water injectionpump 76 flows through a water injection discharge header 78 interposedbetween the water injection pump 76 and the Christmas tree structure 66.The header 78 is a manifold structure that can receive water from anyparallel water treatment units (not shown) and/or that can output wateron parallel paths to any other injection wellheads via respectiveChristmas tree structures (also not shown).

Using a header 78 such as this, water injection arrangements can betailored to the individual reservoir. Separate water/gas injectionsystems 72 could be located at individual wells, or high-pressurein-field lines could distribute injection fluid to multiple wells from asingle water/gas injection system 72.

Where produced water flowing from the water treatment system 54 is to bere-injected, the wet gas could simply be combined with that producedwater. In this example, however, sea water is also drawn from the seaand processed in a filtration and treatment plant 80 to supplement theproduced water by co-mingling, for example in a venturi system, forre-injection. Thus, the wet gas is firstly mixed with the treatedseawater in a gas ejector 82 and then the resulting multiphase mixtureis combined with the produced water in the water injection suctionheader 74.

Moving on now to FIGS. 4 and 5 of the drawings, these show a subseaproduction unit 84 in a practical embodiment of the invention. Likenumerals are used for like features.

FIG. 4 shows the unit 84 installed on the seabed, complete with anelongate supporting frame 86 that surrounds various functional orprocessing modules within the unit 84. Those modules implement thevarious sub-systems of the system 10 described above.

FIG. 5 omits the frame 86 for ease of viewing the positional layout ofthe illustrated modules. The layout shown there is an example that omitssome of the modules required to implement the system 10 described above,which could be provided either onboard the unit 84 or outside andconnected to the unit 84, for example on a neighbouringsimilarly-constructed unit installed on the seabed.

Specifically, the frame 86 of the subsea production unit 84 shown inFIG. 4 comprises a steel deck 88 that supports various processingmodules and their connecting pipework. A GRP superstructure 90 is boltedtogether and connected to the deck 88 so that the deck 88 and thesuperstructure 90 together form a truss structure to carry the heavypayload of the processing plant during towing and installation.Conveniently, buoyancy required for towing the unit 84 to the productionsite may be pre-shaped and assembled into the superstructure 90.

Subsea production units 84 of the invention are apt to be fabricated indry dock facilities. To maximise the choice of available fabricationfacilities, it is important that the size of such units 84 is minimised.By way of example, a subsea production unit 84 as shown in FIG. 4 mayhave a length of about 41.3 m, a width of about 9.2 m and a height ofabout 7.6 m.

An advantage of the GRP/steel hybrid structure of the frame 86 is thatsections of the superstructure 90 can be fabricated at a supplier'spremises and shipped to the launch site to be assembled onto thefoundation of the steel deck 88 in a short period of time. Anothersignificant benefit is that this solution allows for onshoreprefabrication and for a full system check to be performed onshore, orin shallow water inshore, before tow-out to an offshore location.

As is conventional, the superstructure 90 has tapered ends to protectthe unit 84 against over-trawling. Removable GRP cover panels may beprovided on the superstructure to minimise snagging risks andbeneficially to reduce hydrodynamic flow of water within the unit as theunit moves through the water during installation.

Some cover panels, particularly on the sides of the superstructure, canbe removed after installation to facilitate ROV access. Also, theupwardly-facing cover panels 92 on top of the superstructure 90 can beopened to provide apertures for access to the processing modulessupported in upwardly-opening silos on the steel deck 88 beneath.

The processing modules are retrievable from their silos by being liftedthrough the apertures as shown in FIG. 4, which shows a module 94comprising a flowmeter 70 being lifted by a wire 96 hanging from a winchor crane of a surface vessel, not shown. A work-class ROV (WROV) 98 isshown performing and supervising the necessary subsea connection,guiding and monitoring operations. It will be apparent that theaforementioned optional onboard removable sand storage tank may belifted and replaced in a similar fashion.

More generally, subsea processing systems 84 of the invention cancomprise a variety of processing modules depending upon the type ofprocessing needed for a particular field development. To reduce costs,standardised modular designs are preferably used throughout the systemof the invention. This allows providers of subsea processing equipmentto develop their own system modules, and thereafter those modules can beintegrated into the subsea processing unit 84 in much the same way astopside platform modules.

Standardised transport and installation frames 100 surrounding therequired modules can be installed into the subsea processing unit 84 ina plug-and-play fashion. Such frames 100 also help to reduce variationsin terms of handling and installation procedures.

Installation and retrieval of modules may be performed according to thefollowing simplified process:

-   -   1. A module such as a flowmeter module 94 including a transport        and installation frame 100 is lowered from a vessel through a        moonpool of the vessel, where possible, to reduce weather        dependency. Alternatively the module 94 may be lowered over the        side of the vessel.    -   2. The WROV 98 guides the module 94 into an appropriate silo of        the subsea production unit 84 through the top of the unit 84. No        guide wires are required. A handle may be provided on the module        94 for the WROV 98 to grab to apply lateral guide forces to the        module 94. Upwardly-extending guide formations around the silo        guide the transport and installation frame 100 into the correct        position in the unit 84, while also aligning piping and        electrical connectors between the unit 84 and the module 94.    -   3. Once aligned, the module 94 is lowered further into the silo        of the unit 84. Dampers are suitably provided to ensure that the        module 94 will stop softly some 300 mm above the mechanical        connectors. The WROV 98 will then lower the module 94, for        example by a screw mechanism or hydraulically, and mate the        connectors in a fully controlled manner.    -   4. Depending on the module 94, various connections will be        necessary, for example electrical connections, hydraulic        connections and piping. Normally, such connections will be        vertically-oriented, coming up from main piping that runs at the        level of the deck 88. Pipe connections may be made by standard        clamp connectors actuated by the WROV 98.

The water management system of the invention does not need pumps orcompressors demanding a large power supply. However some units such asflowmeters, oil-in-water meters and remote-controlled valves willrequire control cables and minor power cables. Wet-mate connectors areavailable for this purpose. In this way, power can easily be providedin-field from a central power station to remotely-located watermanagement systems.

Turning next to the layout of the modules shown in FIG. 5 andschematically in FIG. 6, a harp gas separator 22 and an array ofparallel DPSs 24 are shown side-by-side. The DPSs 24 of the array aresubstantially parallel to each other, lying side-by-side in an inclinedplane that rises longitudinally with respect to the underlying deck 88of the subsea processing unit 84 shown in FIG. 4.

The gas separator 22 and the DPSs 24 are centralised lengthwise withrespect to the subsea processing unit 84. Centralising these largemasses in longitudinally-inboard positions in this way improves thestability of the unit 84 during transportation and installation. In thisrespect, it will be noted that smaller, lighter modules such as the CFUs58 and the flowmeter 70 are at longitudinally-outboard positions withrespect to the gas separator 22 and the DPSs 24.

The wellstream flows through the gas separator 22 in a firstlongitudinal direction. The degassed wellstream fluid flowing out of thegas separator 22 then enters a branch or manifold 102 that divides thatfluid into a number of flowpaths corresponding to the number of DPSs 24in the array. The manifold 102 also reverses the flow direction into asecond longitudinal direction opposed to the first longitudinaldirection.

Before reaching the respective DPSs 24, the flowpaths first followrespective pre-separator pipe sections 26 that, in this example, arecollapsed longitudinally by being bent or folded sinuously. This definesupper and lower portions 26A, 26B of the pre-separator pipe sections 26that are in mutually-stacked, vertically-spaced relation, and that havemutually-opposed shallow inclination. In this respect, reference is madeto the schematic detail view of FIG. 6.

More specifically, each pre-separator pipe section 26 comprises an upperportion 26A in which the wellstream fluid flows in the secondlongitudinal direction from a manifold end adjacent the liquid outlet ofthe gas separator 22. The upper portion 26A is inclined upwardly in thesecond longitudinal direction, corresponding to the flow direction inthat portion.

A first downward bend 104 at the other end of the upper portion 26Ajoins the upper portion 26A to the lower portion 26B, reversing the flowbetween the upper and lower portions 26A, 26B. Consequently, thewellstream fluid flows in the lower portion 26B in the firstlongitudinal direction, generally parallel to the flow in the gasseparator 22. The lower portion 26B is inclined upwardly in the firstlongitudinal direction, again corresponding to the flow direction inthat portion.

The lower portion 26B, in turn, ends in a second downward bend 106 thatis longitudinally opposed to the first downward bend 104 and that isdisposed under the end of the upper portion 26A adjacent to the manifold102. The second downward bend 106 joins the lower portion 26B to theinlet of the associated DPS 24 and again reverses the flow between thelower portion 26B and the DPS 24. Thus, the wellstream fluid flowsthrough the DPS 24 in the second longitudinal direction. The resultingreversal of flow between the gas separator 22 and the array of DPSs 24facilitates the compact side-by-side disposition of those bulkycomponents.

In this example, the length of the system is also minimised relative tothe use of a standard pipe separator in other ways. Firstly, theinclination of the DPSs 24 shortens their overall length parallel to thelength of the subsea processing unit 84, while maintaining theireffective length. Secondly, the reversal of flow direction in thepre-separator pipe sections 26A, 26B approximately halves their overalllength parallel to the length of the unit 84 compared with theireffective length. Thirdly, most of the upper and lower portions 26A, 26Bof the pre-separator pipe sections 26 are stacked above the DPSs 24rather than being offset longitudinally from the DPSs 24, benefittingfrom the space allowed by the inclination of the DPSs 24.

Conventionally, large specialist offshore construction vessels are usedfor the installation of heavy subsea structures by lifting. Because oftheir size, such structures are often split into smaller components,hence requiring multiple operations for installation and connection.This increases the number of offshore operations and the need for subseaconnection work. The resulting dependence on favourable weather forinstallation becomes an important factor in the cost and risk of aninstallation project.

By combining components such as a manifold, sand removal unit, harp gasseparator, parallel DPSs and serial CFUs in a supporting frame 86 as asubsea processing unit 84, offshore lifting operations and subseaconnection operations are minimised. However, the size and weight of theunit 84 means that it can only be lifted by relatively few availableheavy-lift vessels.

Consequently, other methods of installation are preferred for thepurposes of the invention, such as the towed production systemsexemplified in WO 2014/095942 and WO 2016/071471. In this approach,large subsea processing plants may be assembled in coastal yards assubsea production units 84.

Having assembled and tested the system, the subsea production unit 84can be towed to field using the well-proven Controlled Depth TowingMethod (CDTM). This reduces the cost and risk of installation comparedto lift solutions, due to the reduced need for installation resources.

A controlled-depth tow can be performed in a higher sea states thanoffshore lifting operations and minimises the field access requirementssignificantly. Use of towing installation methods for subsea productionunits 84 reduces the environmental impact and the risk to personnel byminimising the exposure of components. The towing and loweringoperations impose lower dynamic installation forces on the unit 84 thanfor installation by lifting. The duration and cost of the installationoperation can be reduced greatly.

Many variations are possible within the inventive concept. For example,FIGS. 7, 8 and 9 show improved water separation systems in which the oiloutput of the DPS 24 is subjected to a second stage of water separation.These variants are apt to be used in, or in conjunction with, subseaprocessing units 84 like that shown in FIG. 4 but they may also havewider application. Again, like numerals are used for like features.

In each of FIGS. 7, 8 and 9, a wellstream enters a harp gas separator 22that performs bulk gas separation. The wellstream is preferablyde-sanded beforehand but that step has been omitted in these drawingsfor simplicity. As before, the separated wet gas is channelled away forsubsequent use in a water treatment system 54 to clean oil from theproduced water, and optionally also for re-injection into a well.

The degassed wellstream then passes through a DPS 24 that is suitablypreceded by a pre-separator pipe section 26 as before. The pre-separatorpipe section 26 shown in FIGS. 7 and 8 is omitted from FIG. 9 but isoptional. In practice, the pre-separator pipe section 26 and the DPS 24may be shaped and positioned compactly relative to each other like thecorresponding components shown in FIGS. 5 and 6.

In the variants shown in FIGS. 7, 8 and 9, the second stage of waterseparation is performed by an electrocoalescer 108 downstream of the DPS24 in combination with a further liquid-liquid separator in series with,and downstream of, the electrocoalescer 108. That further liquid-liquidseparator is exemplified by a pipe separator 110 in FIG. 7 and by a DPS112 in FIGS. 8 and 9. The latter option is preferred for efficiency andcompactness.

In each case, the further liquid-liquid separator 110/112 outputs:

-   -   oil containing a reduced water fraction, which oil may be sent        to a tank 46 as shown in FIG. 1 for settling, if necessary, and        for periodic offloading; and    -   oily water that is added to the oily water output from the DPS        24 in the first separation stage, before treatment in a water        treatment system 54 that is preferably like that described above        in relation to FIG. 1.

By promoting coalescence of smaller oil droplets into larger oildroplets, the electrocoalescer 108 conditions the mixture of oil andwater flowing from the first-stage DPS 24 to improve the effectivenessof the further liquid-liquid separator 110/112 downstream in the secondstage.

Synergistically, by dewatering the wellstream and by modifying the flow,the first-stage DPS 24 improves the effectiveness of theelectrocoalescer 108 and hence, in turn, the effectiveness of thefurther liquid-liquid separator 110/112 downstream in the second stage.

Also synergistically, by degassing the wellstream upstream of thefirst-stage DPS 24 and by modifying the flow, the gas separator 22improves the effectiveness of the electrocoalescer 108 and hence, inturn, the effectiveness of the further liquid-liquid separator 110/112downstream in the second stage.

These synergies combine beneficially with the aforementioned synergybetween the gas separator 22 and the first-stage DPS 24, which as notedpreviously improves the effectiveness of the first-stage DPS 24.

The result of these various synergies is that substantially more wateris removed from the oil in the wellstream than if only one liquid-liquidseparation stage was used.

Similarly, substantially more water is removed from the oil in thewellstream than if successive liquid-liquid separation stages were usedwithout the intermediate step of promoting coalescence. Also,substantially more water is removed from the oil in the wellstream thanif the preliminary degassing step was omitted before the, or the first,liquid-liquid separation stage.

By virtue of containing substantially less water, the oil output fromthe further liquid-liquid separator 110/112 is less susceptible to theformation of hydrates or other solids that could subsequently plug apipeline or other production equipment.

A challenging consequence of the improved separation of water from theoil in the wellstream is that more water has to be cleaned, preferablysubsea by the water treatment system 54. The preferably two-stageoperation of the water treatment system 54 and the use of CFUs, asdescribed above in relation to FIG. 1, is beneficial to handle thisincreased flow of water while ensuring that the OiW ratio issufficiently low to allow for re-injection or discharge of that water asthe case may be.

FIG. 9 shows that the first-stage DPS 24 shown schematically in FIGS. 7and 8 is preferably an array of parallel, manifolded DPSs 24, in thisexample an array of four DPSs 24. FIG. 9 also shows that thesecond-stage DPS 112 is preferably also an array of parallel, manifoldedDPSs 112, in this example a pair of two DPSs 112. The DPSs 112 of thesecond stage are fewer in number than the DPSs 24 of the first stage toreflect that less water is present to be separated from the oil in thesecond stage than in the first stage.

FIG. 9 also shows, schematically, provisions for controlling theseparation and treatment system to maintain appropriate outputcharacteristics. Similar provisions may of course be added to the systemshown in FIG. 1. In this respect, an Oil-in-Water sensor 114 monitorsthe OiW ratio in water produced by the water treatment system 54 and aWater-in-Oil sensor 116 monitors the WiO ratio in oil exiting thesecond-stage DPSs 112. Optionally, a further Water-in-Oil sensor maymonitor the WiO ratio in oil exiting the first-stage DPSs 24. Bothsensors 114, 116 report to a control system 118 that, in turn, controlsappropriate valves 120 to modify the flow of fluids in the system, ifrequired, to maintain the desired output characteristics.

1. A subsea production unit for subsea treatment of oil, the unitcomprising a frame that supports: an onboard multiphase separationsystem for separating gas and water from a wellstream containing oil;and an onboard water treatment system for cleaning oil from water thatis produced by the separation system, wherein the water treatment systemcomprises a gas inlet communicating with the separation system and isarranged to mix the produced water with gas separated from the oil,wherein the water treatment system has a further input to receive watersettling in a storage tank, and wherein the storage tank is an onboardtank also supported by the frame.
 2. The unit of claim 1, wherein thewater treatment system comprises at least one flotation unit having: awater inlet for water to be cleaned of oil; a water outlet for watercleaned of oil; and a reject outlet for gas mixed with oil cleaned fromthe water.
 3. The unit of claim 2, wherein the water treatment systemcomprises first and second flotation units in series, the water outletof the first flotation unit communicating with the water inlet of thesecond flotation unit.
 4. The unit of claim 2, wherein the water inletof the or each flotation unit communicates with a mixer for mixing gaswith water to be cleaned of oil.
 5. The unit of claim 1, wherein thewater treatment system comprises a discharge outlet for discharge of thecleaned water into surrounding seawater.
 6. The unit of claim 1, whereinthe water treatment system communicates with a water injection systemfor injecting the cleaned water into a subsea reservoir.
 7. The unit ofclaim 6, wherein the water injection system comprises a gas inletcommunicating with the separation system and is arranged also to receiveand inject gas separated from the oil.
 8. The unit of claim 6, whereinthe water injection system comprises a processed water inletcommunicating with a seawater processing system and is arranged also toreceive and inject processed water drawn from surrounding seawater. 9.The unit of claim 5, further comprising an oil-in-water sensorassociated with a cleaned water outlet of the water treatment system.10. The unit of claim 1, wherein the separation system comprises a gasseparator upstream of a water/oil separator.
 11. The unit of claim 10,wherein the gas separator and the water/oil separator are atcorresponding longitudinal positions with respect to a length directionof the unit.
 12. The unit of claim 11, wherein the gas separator isbeside the water/oil separator and fluid flow through the water/oilseparator is in a substantially opposite direction to fluid flow throughthe gas separator with respect to the length direction.
 13. The unit ofclaim 10, further comprising a water-in-oil sensor associated with anoil outlet of the water/oil separator.
 14. The unit of claim 10, whereinthe water/oil separator comprises at least one dual pipe separator. 15.The unit of claim 14, wherein the water/oil separator comprises an arrayof parallel dual pipe separators.
 16. The unit of claim 14, furthercomprising a pre-separator pipe section upstream of the or each dualpipe separator.
 17. The unit of claim 16, wherein the pre-separator pipesection is folded sinuously to define upper and lower portions inmutually-stacked, vertically-spaced relation.
 18. The unit of claim 17,wherein the upper and lower portions of the pre-separator pipe sectionhave mutually-opposed inclination.
 19. The unit of claim 17, wherein theflow direction reverses between the upper and lower portions of thepre-separator pipe section.
 20. The unit of claim 17, wherein the upperand lower portions of the pre-separator pipe section incline upwardly ina flow direction within each portion.
 21. The unit of claim 17, whereinthe upper and lower portions of the pre-separator pipe section arestacked above the dual pipe separator.
 22. The unit of claim 1, whereinthe separation system further comprises a sand removal unit upstream ofthe gas separator.
 23. The unit of claim 22, wherein the separationsystem further comprises a retrievable sand storage tank for receivingsand from the sand removal unit.
 24. The unit of claim 1, whereincomponents of the respective onboard systems are modularly replaceablesubsea by lifting, without lifting the frame.
 25. The unit of claim 24,wherein the frame defines upwardly-opening silos arranged to accommodatethe respective components.
 26. The unit of claim 25, wherein thecomponents are supported in respective transport and installationstructures that are engageable with the silos of the frame for verticalmovement relative to the frame on installation or removal.
 27. The unitof claim 1, wherein the frame is a unitary structure that istransportable by towing or lifting while supporting components of therespective onboard systems.
 28. A method of separating fluids from amultiphase oil-containing wellstream, the method comprising: separatinggas and water from the wellstream to produce oil; cleaning oil from thewater that is produced by the separation step and mixing the producedwater with gas separated from the wellstream in the separation step; andperforming the cleaning step also on water settled from oil produced bythe separation step; the separation and cleaning steps both beingperformed subsea onboard a transportable subsea production unit.
 29. Themethod of claim 28, comprising cleaning oil from the produced water bypassing the produced water through at least one flotation unit.
 30. Themethod of claim 29, comprising passing the produced water through firstand second flotation units in series, the water output from the firstflotation unit being input to the second flotation unit.
 31. The methodof claim 28, comprising discharging the produced water into surroundingseawater after cleaning.
 32. The method of claim 31, comprisingmaintaining an oil-in-water ratio of the discharged produced water below30 ppm.
 33. The method of claim 28, comprising injecting the producedwater into a subsea reservoir after cleaning.
 34. The method of claim33, further comprising injecting, with the produced water, gas separatedfrom the wellstream in the separation step.
 35. The method of claim 33,further comprising injecting, with the produced water, processed waterdrawn from surrounding seawater.
 36. The method of claim 28, comprisingeffecting gas separation on the wellstream upstream of water separationon the wellstream.
 37. The method of claim 36, comprising performingwater separation in at least one dual pipe separator.
 38. The method ofclaim 37, comprising conditioning the wellstream in a pre-separator pipesection downstream of gas separation and upstream of the dual pipeseparator.
 39. The method of claim 38, comprising guiding the wellstreamto follow a sinuous path in the pre-separator pipe section.
 40. Themethod of claim 39, comprising guiding the wellstream to reverse in flowdirection in the pre-separator pipe section.
 41. The method of claim 28,preceded or followed by transporting the subsea production unit to orfrom a subsea location.